1. Field of the Invention
The present invention relates to oil field downhole tools and wellhead equipment.
2. Description of the Related Art
Oil field wells are typically controlled by a “stack” of equipment for supporting downhole “strings” of tubulars, such as casing and tubing, valves, and other equipment to manage the drilling and production pressurized fluids in a well. A “conductor” pipe or casing is generally the first string of casing placed in the open hole to prevent the soil formations near the surface from caving in. An initial “surface” casing is the first string of casing that is placed in a well after the conductor. A wellhead typically sits on top of a base plate mounted on the conductor and provides controlled access to the wellbore during drilling and production. Various spools, a tubing head, and valves can be assembled thereto. As the wellbore depth increases, additional smaller casings can be placed inside the surface casing to extend to the deeper portions of the well. The additional casings are supported in the stack by supporting surfaces in the wellhead, a casing hanger held in the wellhead, and/or a casing spool mounted to the wellhead.
When the well is completed at a certain depth and cement is placed around the outer surface of the casing, production tubing is installed to the desired production depth in a similar arrangement by supporting the tubing from a tubing hanger in the wellhead. A blowout preventer (“BOP”) is usually installed in the stack to control the well if an overpressure condition occurs. In the past, the stack and particularly the BOP were disassembled for access to the wellbore to place another size casing or tubing. The system needed to be pressure tested after each reassembly, costing significant expense and time. Also, because the wellbore could have significant pressure during the interim access without the blowout preventer, the disassembly and reassembly was hazardous.
Over the last 100 years, the improvements in the drilling and production systems typically have been small, incremental adjustments to satisfy specific needs as deeper wells were drilled and produced sometimes with higher pressures, faster drilling, less disassembly and assembly, and other improvements. One improvement in recent years is a “unitized” wellhead. The unitized wellhead facilitates using different sizes of casing and tubing without having to disassemble major portions of the stack or remove the blowout preventer. One such unitized wellhead is available from T3 Energy Services, Inc. of Houston, Tex., USA. The assembled unitized wellhead includes a lower casing head and an upper casing spool that are coupled together and installed as a single unit. As smaller sizes of casing strings are needed, different casing hangers can be progressively cascaded and installed within the bore of the unitized wellhead for supporting the casing stings without removing the BOP. When a casing is set and cemented in place, a support pack-off bushing can be installed above the casing hanger to both seal the annulus below the casing hanger and the wellhead flanges, and create a landing shoulder for the tubing hanger. A tubing head can be installed above the unitized wellhead casing spool to house the tubing hanger.
Another improvement in recent years is the “thru diverter” type wellhead. Such a wellhead allows for lower cost drilling on smaller or marginal formations. A thru diverter wellhead is particularly useful in “batch drilling,” which makes efficient use of a larger more expensive drilling rig to drill a number of wells. In batch drilling, after the drilling of a well is completed, the well may be capped, and the rig moved to another well location. The wells can be completed later by smaller more economical rigs.
There are several limitations with the existing thru diverter type wellheads. Although the wellheads may be placed in some larger diverters, there is minimal clearance since there are numerous housings and other protrusions typically welded to the wellhead's exterior surface. Further, the exterior surfaces of the wellheads are uneven and non-uniform. Thus, the size of the wellhead that will move thru the diverter is limited. The wellheads will not fit at all in some smaller diverter housings. Further, such limited size wellheads only allow for the positioning of a single casing hanger with a single casing string.
There are also challenges to placement and operation of existing thru diverter type wellheads. There may be external threads on the exterior surface of the wellhead for attachment of the wellhead with other components of the stack. Further, there may be a groove on the exterior surface of the wellhead and a seal for sealing with other components of the stack. The seal, thread and/or the groove may be damaged either during placement of the wellhead or during an operation. An undamaged seal, thread and groove are necessary for the wellhead to maintain its maximum rated pressure after assembly of the stack. Damage to the seal, thread and/or groove will likely not be discovered until after the wellhead is permanently cemented in place with the wellbore, making replacement of the wellhead, at best, difficult. Time consuming and expensive field work may be needed to repair the damaged seal, thread and/or groove, with resulting lost time. The maximum pressure that the wellhead system may maintain may be compromised if a complete repair cannot be made. For example, if the groove cannot be completely repaired, then a lower pressure rated annular seal may be need to be used, which may lower the maximum rated pressure for the wellhead. The result may be a compromised plan for the well.
To protect the interior surface of the existing thru diverter wellhead during cementing and drilling operations, a removable protective sleeve has been positioned within the wellhead, which results in the loss of valuable rig time. Otherwise, cement or drilling fluid contaminants such as sand, rock and/or debris may damage the wellhead. Further, in some operations, there is an unmet need to bring tubulars, such as 4½ inch (11.4 cm) diameter casing or liners, completely back to the surface without disassembling the BOP stack. This would help solve some geological based drilling problems, as well as minimize rig time and mitigate a safety issue, as discussed above.
Another recent improvement in drilling involves the method of counteracting downhole pressures. In the past, drilling has been accomplished by providing a drilling fluid “mud” to weigh down and counteract fluids in the wellbore sometimes with large upward pressures. The weighted mud is pumped downhole while drilling occurs, so that the wellbore pressure is controlled. By controlling the well fluids from rising to the surface, difficult and hazardous conditions are mitigated. However, using such mud increases costs and drilling time, and can counterproductively damage the hydrocarbon formation that is to be produced. Improvements have been made in drilling by reducing use of the mud through techniques sometimes referred to as “underbalanced drilling” and “managed pressure drilling.” The drilling can proceed with less heavy mud and the drilling is typically faster with less down time.
A “downhole deployment valve” has been inserted down the wellbore in the past as a type of one-way check valve attached to the casing to block the downhole well fluids under pressure from escaping up through the casing. The downhole deployment valve is typically set at a certain depth and remains at that depth while drilling continues to greater depths. The drill pipe, bit, and other drill assembly devices are sized to be inserted through the downhole deployment valve to drill the wellbore. When the drill string is removed back through the downhole deployment valve, the downhole deployment valve can be closed to seal the downhole fluids. Therefore, when the drill bit is changed or the drill string is otherwise “tripped,” the operation can be done easier and generally safer because the casing above the downhole deployment valve can be vented to atmosphere while the pressurized fluids are controlled by the downhole deployment valve. Hydraulic control lines from the surface wellhead allow the pressurization of hydraulic fluid downhole to open and close the downhole deployment valve. Therefore, the control lines are used to remotely and selectively control the operation of the downhole deployment valve.
While the downhole deployment valve has been deemed an improvement, there have been challenges with protecting the integrity of the flow of the hydraulic fluid in the control lines for controlling the downhole deployment valve. Typically, the hydraulic fluid must move through the wellhead in fluid passageways from ports at the exterior surface of the wellhead to corresponding ports at the wellhead's interior surface. In past installations, the downhole deployment valve is typically coupled or strapped to a section of casing and a casing hanger is installed on the opposite end of the casing. Control lines are run from the downhole deployment valve up to hydraulic ports on the bottom of the casing hanger. Fluid passageways in the casing hanger allow fluid communication between respective ports on the bottom of the hanger and ports on the side of the hanger.
The downhole deployment valve, casing, and casing hanger are lowered into the wellhead, until the casing hanger sits on an internal shoulder of the wellhead. U.S. Pat. No. 6,244,348 proposes a tubing hanger with an internal passageway for conveying fluids with a port on a mating surface for sealing with the internal wellhead seal surface, with a check valve positioned within the hanger port to interface with the internal wellhead seal surface. The hydraulic fluid is transported through the wellhead in a passageway for conveying fluids. U.S. Pat. No. 4,623,020 proposes a tubular body with a passageway for conveying fluids with a port on an exterior sealing surface to form a slidable fluid seal with the interior surface of a wellhead adapter member that also has a fluid passageway, which member is provided with a number of elastomeric seals spaced annularly around its interior surface. In practice, the seals, which are located near where the hanger side port interfaces with the port on the interior surface of the wellhead, leak due to the sand, rock, and other debris and contaminants in the drilling fluid passing through the wellhead and wellbore from the drilling operations. The ports and hydraulic fluid can be contaminated and cause control issues with the downhole deployment valve. The control lines can also be compromised from external forces. In addition, equipment can impact the control lines, operators may unintentionally step on the control lines, and other physical damage can occur to the control lines that can render the system inoperative and potentially hazardous to operators nearby.
Pub. No. U.S. 2004/0079532 proposes a single bowl casing head that has one or more access openings or side bores through its sidewall for placement of a single hydraulic line in each opening. The casing head proposed in the '532 publication only allows for the positioning of one casing hanger.
The above discussed U.S. Pat. Nos. 4,623,020 and 6,244,348; and Pub. No. U.S. 2004/0079532 are hereby incorporated by reference for all purposes in their entirety.
There remains a need for a thru diverter type wellhead that allows for the direct coupling of hydraulic control lines and related system to operate a downhole deployment valve and other downhole tools. It would be desirable to run the wellhead thru the diverter without housings and other protrusions extending from the exterior surface of the wellhead during installation so as to increase the size of the wellhead that may be moved relative to the diverter. It would further be desirable for such a wellhead to accommodate more than one casing hanger and casing string, and allow for tubulars to be brought back to the surface without disassembling the BOP stack. It would also be desirable to eliminate the need for a tubing head in certain circumstances. It would also be desirable to have a system and method that would protect the wellhead during its placement and operation. It would further be desirable to eliminate the need to install a temporary protective sleeve in wellhead during certain cementing and drilling operations.